Methods and apparatus to optimize steam header blending and gas turbine loading in combined cycle power plants

Abstract

Methods and apparatus to optimize ramp rates in combined cycle power plants are disclosed herein. An example method disclosed herein includes predicting a first setpoint for a gas turbine in a combined cycle power plant over a prediction horizon and predicting a second setpoint for a steam generator over the prediction horizon. The example method includes identifying a first steam property of steam generated by the steam generator in the combined cycle power plant based on the second setpoint. The example method includes comparing the first steam property to a second steam property of steam associated with a steam turbine in the combined cycle power plant and dynamically adjusting at least one of the first setpoint or the second setpoint based on the comparison.

What is claimed is: 
     
       1. A method comprising:
 predicting a first setpoint for a gas turbine in a combined cycle power plant for a prediction period based on a process constraint for the gas turbine and a first prediction model; 
 modifying a second prediction model based on an operating condition at a steam generator to generate a modified second prediction model; 
 predicting a second setpoint for the steam generator for the prediction period based on a process constraint for the steam generator and the modified second prediction model; 
 measuring a first steam property of steam generated by the steam generator in the combined cycle power plant based on the second setpoint; 
 comparing the first steam property to a corresponding second steam property of steam associated with a steam turbine in the combined cycle power plant; and 
 dynamically adjusting at least one of the first setpoint or the second setpoint based on the comparison. 
 
     
     
       2. The method of  claim 1 , wherein the first steam property is one of a steam pressure value, a steam temperature value, or a steam enthalpy value. 
     
     
       3. The method of  claim 1 , wherein the first setpoint is one of a load setpoint or an exhaust gas temperature setpoint. 
     
     
       4. The method of  claim 1 , further including:
 identifying a difference between the first steam property and the second steam property; and 
 dynamically adjusting the at least one of the first setpoint or the second setpoint based on the difference. 
 
     
     
       5. The method of  claim 1 , further including predicting the second setpoint based on a target setpoint for the steam generator. 
     
     
       6. The method of  claim 5 , wherein the target setpoint is based on the second steam property of the steam associated with the steam turbine. 
     
     
       7. The method of  claim 2 , wherein the first steam property is the steam pressure value and the second setpoint is a pressure setpoint. 
     
     
       8. The method of  claim 3 , wherein the first setpoint is the load setpoint and wherein predicting the first setpoint is based on a maximum ramp rate for the gas turbine. 
     
     
       9. The method of  claim 3 , wherein the first setpoint is the load setpoint and wherein the adjusting includes reducing the load setpoint. 
     
     
       10. The method of  claim 1 , wherein predicting the second setpoint is based on the second steam property of the steam associated with the steam turbine or a third steam property of the steam associated with the steam turbine. 
     
     
       11. The method of  claim 1 , wherein the second steam property includes a steam pressure value at a header of the steam turbine. 
     
     
       12. The method of  claim 1 , wherein adjusting includes adjusting the first setpoint based on a target time for transitioning the gas turbine from a non-operating state to an operating state. 
     
     
       13. The method of  claim 1 , wherein predicting the first setpoint is based on an operating condition of the gas turbine. 
     
     
       14. A method comprising:
 predicting a first setpoint for a gas turbine in a combined cycle power plant for a prediction period; 
 predicting a second setpoint for a steam generator during for the prediction period, wherein the second setpoint is to be predicted for a first pressure level section of the steam generator; 
 measuring a first steam property of steam generated by the steam generator in the combined cycle power plant based on the second setpoint; 
 comparing the first steam property to a corresponding second steam property of steam associated with a steam turbine in the combined cycle power plant; and 
 dynamically adjusting at least one of the first setpoint or the second setpoint based on the comparison; 
 predicting a third setpoint for a second pressure level section of the steam generator; 
 measuring a third steam property of steam generated at the second pressure level section; 
 comparing the third steam property to a corresponding fourth steam property of steam associated with a second steam turbine in the combined cycle power plant; and 
 dynamically adjusting at least one of the first setpoint, the second setpoint, or the third setpoint based on the comparison of the third steam property to the fourth steam property.